The injection of steam to recover oil from heavy oil formations is an accepted method in the industry and accounts for nearly 80% of total U.S. enhanced oil recovery. Past experiments and field performance have shown the improved displacement efficiency of heavy oils by reduction in viscosity of the oil by a heated displacing phase. Displacement of oil increases with increasing temperature. Despite its success, it typically leaves behind 30-40% of the original oil in place. One reason is reservoir heterogeneities which, together with relatively low density and viscosity of steam, causes rapid communication between injector and producer wells. The result is reduced sweep efficiency and lower oil recovery.
Steam is considerably lighter than the oil and water present in the formation and thus, because of gravity segregation, it tends to rise to the top of the formation when vertical communication exists. Consequently, the injected steam channels through the top of the formation to the producing well overriding a major portion of the formation and contacting only a small fraction of the formation oil. Once steam override has begun, continued injection of steam into the formation will accomplish very little additional oil recovery. This behavior results in an inefficient oil recovery and low vertical sweep efficiency.
A similar conformance problem exists with carbon dioxide flooding. Carbon dioxide has a great tendency to channel through oil-in-place since carbon dioxide viscosity may be 10 to 50 times lower than the viscosity of the oil-in-place.
Laboratory and field test results have demonstrated that foam may be used to improve sweep efficiency. In steam flooding, the process is referred to as steamfoam. A typical steamfoam process involves coinjection of a small amount of surfactant with steam or with a noncondensible gas, such as nitrogen and steam. The steam vapor, or the nitrogen and the steam vapor disperses in the surfactant solution and generates foam. Because of its gas-like density, foam tends to override the steam and enter the more permeable and the well swept zones. Because of its high viscosity, it flows at a slower rate and allows steam to be diverted to the unswept zones with high oil saturation. The diverted steam contacts the oil and recovers it. A typical steamfoam process involves the injection of 0.2-1% weight surfactant in the liquid phase and 0.1-2 mole percent nitrogen in the gas phase.
In addition, numerous patents have been issued on the recovery of oil using a foam-forming mixture of steam, noncondensible gas and surfactant which includes U.S. Pat. Nos. 4,086,964; 4,488,598; 4,570,711; 4,852,653 and 4,971,150.
U.S. Pat. 4,607,695 discloses a steamfoam process in which steam is injected into the formation having a natural brine salinity concentration within the range of 10 to 20% by weight until steam breakthrough occurs at the production well after which a mixture of steam, a noncondensible gas, and a surfactant comprising a C.sub.12 alpha olefin sulfonate is injected into the formation. The C.sub.12 alpha olefin sulfonate forms a stable foam with the formation oil at formation conditions that reduces the permeability of the highly permeable steam swept zones thereby diverting the steam to other portions of the formation containing unswept oil.
The present invention provides an improved method for recovering oil from an oil-containing formation utilizing an aqueous surfactant-starch solution mixed with carbon dioxide or with steam and a noncondensible gas that stabilizes the foam effecting a reduction in permeability of steam-swept or carbon dioxide-swept channels thereby enabling subsequently injected steam or carbon dioxide to migrate into additional portions of the formation containing unswept oil. The use of an aqueous mixture of surfactant and starch as the foam-forming mixture produces a stable foam and also results in a reduced amount of surfactant without reducing the effectiveness of the surfactant.